Method and system for separating and destroying sour and acid gas

ABSTRACT

A system adapted to separate a natural gas feed stream into a sweetened gas stream, at least one liquid waste stream and at least one gaseous waste stream, and to discharge, recover or destroy the at least one liquid waste stream and the at least one gaseous waste stream. The system includes a compression subsystem adapted to treat the natural gas feed stream to remove a first portion of the at least one liquid waste stream and to increase the natural gas teed stream to a process pressure greater than an initial entering pressure to form a pressurized natural gas stream, a gas pretreatment subsystem adapted to treat the pressurized natural gas stream to remove a second portion of the at least one liquid waste stream and to cool and filter the pressurized natural gas stream to form a filtered natural gas stream, an acid gas separation subsystem adapted to separate the filtered natural gas stream into the sweetened gas stream and a first portion of the at least one gaseous waste stream, and an destruction subsystem adapted to incinerate the first portion of the at least one gaseous waste stream to form a flue gas.

CROSS-REFERENCE TO RELATED APPLICATIONS

This patent application claims the benefit under 35 U.S.C. §119(e) ofU.S. Provisional Patent Application No. 61/601,812, filed Feb. 22, 2012,which application is incorporated herein by reference.

TECHNICAL FIELD

The presently disclosed embodiments are directed to producing useablenatural gas from sour and acid gas, as well as eliminating carbon andsulfur dioxide atmospheric pollution produced by burning of contaminatednatural gas. The presently disclosed embodiments may be used on maritimeplatforms and land based sour and/or acid gas sources.

BACKGROUND

Natural gas, a gas mixture formed primarily of methane which may alsoinclude ethane, propane, butane, pentane and higher molecular weighthydrocarbons, is a vital component of the world's supply of energy as asource of providing heat and electricity, and fuel for vehicles. It isalso used as a chemical feedstock in the manufacture of plastics andother commercially important organic chemicals. Natural gas may beharvested or synthesized as a primary product or may be a byproduct ofother oil exploration activities, and is abundant in the United States.Natural gas is clean burning and emits lower levels of potentiallyharmful byproducts into the air than some other fossil fuels. Naturalgas is found in deep underground natural rock formations or associatedwith other hydrocarbon reservoirs in coal beds and as methaneclathrates. Petroleum is also another resource found in proximity to andwith natural gas.

Different types of natural gas are found in a variety of sources.Associated petroleum gas (APG), also known as flare gas, is natural gasfound in association with deposits of petroleum. APG has beenhistorically released as a waste product from the petroleum extractionindustry. Due to the remote location of many oil fields, either at seaor on land, APG is considered a nuisance byproduct and is typicallyburned off using a gas flaring device. Over 150 billion cubic meters ofNM type natural gas are flared or vented annually by World Bankestimates, which is approximately equal to about 25% of the natural gasconsumed in the USA in 2012. Shale gas is natural gas formed from beingtrapped within shale formations. Shale gas has become an increasinglyimportant source of natural gas in the United States since 2000, whenshale gas provided only 1% of U.S. natural gas production. With thedevelopment of hydrofracturing technology, by 2010 shale gas representedover 20% of U.S. natural gas production, and predictions indicate thatshale gas will represent 46% of the U.S. natural gas supply by 2035.Coal bed methane (CBM) results when methane is adsorbed into the solidmatrix of coal. CBM is also referred to as “sweet gas” due to its lackof hydrogen sulfide. CBM is distinct from typical sandstone or otherconventional gas reservoirs, as the methane is stored within the coal bya process called adsorption. The methane is in a near-liquid state,lining the inside of pores within the coal. CBM typically comprises lowlevels of H₂S and CO₂. Biogas methane can be generated as a byproduct ofanaerobic biochemical activity. Digesters, landfills and commercialbiogas generators are used for converting man-made wastes into energy,i.e., biogas methane.

Natural gas is colorless, shapeless, and odorless in its pure form, andis combustible. It is one of the cleanest, safest, and most useful ofall energy sources. When burned, natural gas gives off a great deal ofenergy and while producing few emissions. In other words, natural gas isclean burning and emits lower levels of potentially harmful byproductsthan other fossil fuels. While natural gas is formed primarily ofmethane, it can also include ethane, propane, butane, pentane and highermolecular weight hydrocarbons. Natural gas does not typically exist as apure hydrocarbon mixture, but includes other components as shown inTable 1 below. In some gas fields, higher molecular weight petroleumliquids can be associated with natural gas. These liquids bringadditional commercial value to the natural gas.

TABLE 1 Composition of Natural Gas - representative Methane CH₄ 70-90% Heavier hydrocarbons C₂H₆+ 0-20%  Carbon Dioxide CO₂ 0-8% Oxygen O₂0-0.2%  Nitrogen N₂ 0-5% Water vapor H₂O 0-1% Particles trace Hydrogensulfide H₂S 0-5% Rare gases Ar, He, Ne, Xe trace

Natural gas is generally classified based on the quantity of acidicgases present in the mixture, i.e., primarily hydrogen sulfide andcarbon dioxide. Sweet gas is natural gas of a quality that is pureenough to be commercially used, typically <2% carbon dioxide and <25parts per million hydrogen sulfide. In order to be useable, natural gasmust either be sweet gas direct from the source or must be treated tosweet gas levels. Sour gas is natural gas or any other gas containingsignificant amounts of hydrogen sulfide (H₂S), which can be as high as25%. However, the threshold of what is considered significant varies bycountry, state, or even agency or application. Acid gas is generallyclassified as natural gas or any other gas mixture containingsignificant quantities of acidic gases, typically hydrogen sulfide(H₂S), carbon dioxide (CO₂), or similar acidic contaminants which can begreater than 25%.

A variety of environmental problems are associated with harvestingnatural gas. Generally, when a gas well is developed, i.e., completion,but before the natural gas is harvested for commercial use, the initialgas must be purged as it is generally not usable. Historically, theinitial gas has been burned using flaring equipment. Regulatory agenciesworldwide are putting substantial pressure to eliminate this practiceand are moving to green completion strategies. Associated petroleum gas,i.e., APG, was historically not considered a commercial product.Generally, the main objective is to recover crude oil, and theassociated gas is merely an unwanted byproduct that is just flared. Asoil wells mature, APG can become increasingly contaminated with H₂S andCO₂. As such, flaring puts substantial amounts of carbon into theatmosphere. Moreover, flaring sour gas generates substantial amounts ofSO₂ which converts to H₂SO₄ in the atmosphere, which leads to acid rain.With more stringent regulations on flaring and greater public awarenessof global warming, oil producers are faced with handling APG in a moreenvironmentally way. Although the foregoing environmental issues arepresent regardless of the location of oil exploration, exploration andproduction activities offshore have limited options currently forhandling APG, and specifically sour and acid gas. APG associated withocean platforms raise serious issues as the exploration and productionactivities offshore presently have limited options for handling APG, andspecifically sour and acid gas.

Known natural gas handling procedures suffer from a variety ofdrawbacks. Flaring has historically been the most common treatmentmethod as it is simple and low monetary cost; however, it is likely tobecome increasingly restricted within the foreseeable future due tochanges in various regulations. Deep well injection, i.e., reinjectionof the sour gas, has also been used as a method of handling sour gas. Itis believed that this activity merely delays the problem as thereinjected gas eventually may return to the source reservoir or well.With respect to conveying sour gas to shore from maritime platforms,various methods have been used to convey acid gas to shore. Since thegas is extremely corrosive, exotic and expensive materials must be usedin building the necessary pipelines. Once the sour or acid gas arriveson shore, it still requires treatment to make it useable. Sour or acidgas handling may comprise amine process on platform or on shore. Beforea raw natural gas containing hydrogen sulfide or carbon dioxide can beused, the raw gas must be treated to remove those impurities toacceptable levels, commonly accomplished by an amine gas treatingprocess. The removed H₂S is most often subsequently converted toby-product elemental sulfur in a Claus processor, or it can be treatedin a wet sulfuric acid process unit where the by-product is sulfuricacid. The foregoing amine process has commercial limitations on high H₂Sand CO₂ content streams. Furthermore, amine systems have limitedcommercial use on platforms. They are very expensive, large, require theuse of chemicals and generate substantial amounts of process byproductsthat need to be transported to shore for disposal or reuse.

Heretofore, the oil and gas exploration industry, has been faced withcapturing and handling natural gas in an environmentally responsibleway; however, known systems are complex and expensive. As sour and acidgas must be treated not only at land operations but also on maritimeplatforms, a solution is needed that can address a variety of problems.There has been a long felt need and thus the present method and systemincludes: a small foot print; a minimum weight; a simple, easy operatingprocedure; flexibility to treat different stream chemistries, such as itmust be able to handle high concentration of H₂S and down hole chemistryadditions for controlling scaling and corrosion; use of minimumconsumables and chemicals; minimum waste generation; cost effectiveoperation; and, conversion of wastes to usable products; the capacity tosubstantially reduce the amounts of H₂S, CO₂ and water so that standardpipeline material can be used to convey natural gas to shore.Furthermore, there has been a long felt need for a method and system ofproducing fuel gas by treating acid and sour gas to an acceptablequality to be used to drive compressors and electrical generators on themaritime platforms. Still yet further, there is a long felt need fornatural as being of sufficient quality for use in enhanced oil recovery(EOR) so that it does not contaminate crude oil reservoirs as the gas isinjected to recover oil. In view of the foregoing, it can be seen anovel system and method are needed to extract sweetened gas from sourand acids gas feeds that minimize the addition of carbon and sulfurdioxide to the atmosphere, while meeting water and air regulatoryrequirements.

SUMMARY

Broadly, the present invention discussed infra provides a system adaptedto separate a natural gas feed stream into a sweetened gas stream, atleast one liquid waste stream and at least one gaseous waste stream, andto discharge, recover or destroy the at least one liquid waste streamand the at least one gaseous waste stream. The system includes acompression subsystem adapted to treat the natural gas feed stream toremove a first portion of the at least one liquid waste stream and toincrease the natural gas feed stream to a process pressure greater thanan initial entering pressure to form a pressurized natural gas stream,and a gas pretreatment subsystem adapted to treat the pressurizednatural gas stream to remove a second portion of the at least one liquidwaste stream and to cool and filter the pressurized natural gas streamto form a filtered natural gas stream. The system further includes anacid gas separation subsystem adapted to separate the filtered naturalgas stream into the sweetened gas stream and a first portion of the atleast one gaseous waste stream, and an destruction subsystem adapted toincinerate the first portion of the at least one gaseous waste stream toform a flue gas.

In some embodiments, the compression subsystem includes at least one of:a liquid separation unit adapted to treat the natural gas feed stream toremove the first portion of the at least one liquid waste stream; and, acompressor adapted to increase a pressure of the natural gas feed streamto the process pressure. In some embodiments, the gas pretreatmentsubsystem includes at least one of: a gas cooler adapted to cool thepressurized natural gas stream; a liquid separation unit adapted totreat the pressurized natural gas stream to remove the second portion ofthe at least one liquid waste stream; a heat exchanger adapted to coolthe pressurized natural gas stream; and, a gas filter adapted to treatthe pressurized natural as stream to remove particulates and watervapor. In some embodiments, the acid gas subsystem includes at least oneof: a first membrane separator adapted to separate the filtered naturalgas stream into the sweetened gas stream and the first portion of the atleast one gaseous waste stream; a second membrane separator adapted totreat the sweetened gas stream to remove a second portion of the atleast one gaseous waste stream; and, a polisher adapted to polish thesweetened gas stream. In some embodiments, the destruction subsystemincludes at least one of: an incinerator adapted to combust the firstportion of the at least one gaseous waste stream; and, a heat exchangeradapted to cool the flue gas.

In some embodiments, the system further includes a feed waterpretreatment subsystem adapted to filter a water stream to form afiltered water stream, wherein the filtered water stream cools thepressurized natural gas stream in the gas pretreatment subsystem. Insome embodiments, the feed water pretreatment subsystem includes atleast one of: a first continuous particle filter adapted to filter thewater stream; a second continuous particle filter adapted to filter thewater stream; and, a chemical feeder adapted to condition the filteredwater stream.

In some embodiments, the system further includes a scrubber reactorsubsystem adapted to receive the filtered water stream and to remove atleast one portion of the flue gas using the filtered water stream toform a vent gas stream and a wastewater stream, wherein the vent gas isexhausted to the atmosphere. In some embodiments, the scrubber reactorsubsystem includes at least one of: a scrubber reactor adapted to removeat least one portion of the flue gas using the filtered water stream;and, a blower adapted to provide air to the scrubber reactor.

In some embodiments, the system further includes a wastewater treatmentsubsystem adapted to filter the wastewater stream to form a dischargewater stream. In some embodiments, the wastewater treatment subsystemincludes at least one of: a particulate filter adapted to removeparticulates from the wastewater stream; a metal unit adapted to removemetal from the wastewater stream; and, a mercury unit adapted to removemercury from the wastewater stream.

According to aspects illustrated herein, there is provided a method forseparating a natural gas feed stream into a sweetened gas stream, atleast one liquid waste stream and at least one gaseous waste stream, andfor discharging, recovering or destroying the at least one liquid wastestream and at least one gaseous waste stream. The method includes: a)treating the natural gas feed stream to remove a first portion of the atleast one liquid waste stream; b) pressurizing the natural gas feedstream to a process pressure greater than an initial entering pressureto form a pressurized natural gas stream; c) treating the pressurizednatural gas stream to remove a second portion of the at least one liquidwaste stream; d) cooling and filtering the pressurized natural gasstream to form a filtered natural gas stream; e) separating the filterednatural gas stream into the sweetened gas stream and a first portion ofthe at least one gaseous waste stream; and, f) incinerating the firstportion of the at least one gaseous waste stream to form a flue gas.

In some embodiments, the method further includes: c1) filtering a waterstream to form a filtered water stream, wherein the filtered waterstream in part cools the pressurized natural gas stream in step d). Insome embodiments, the method further includes: g) removing at least oneportion of the flue gas using the filtered water stream to form a ventgas stream and a wastewater stream; and, h) exhausting the vent gas tothe atmosphere. In some embodiments, the method further includes: i)filtering the wastewater stream to form a discharge water stream.

Other objects, features and advantages of one or more embodiments willbe readily appreciable from the following detailed description and fromthe accompanying drawings and claims.

BRIEF DESCRIPTION OF THE DRAWINGS

Various embodiments are disclosed, by way of example only, withreference to the accompanying drawings in which corresponding referencesymbols indicate corresponding parts, in which:

FIG. 1 is a first portion of a schematic diagram of a present inventionsystem for separating and/or destroying sour and acid gas depicting acompression subsystem and a gas pretreatment subsystem;

FIG. 2 is a second portion of a schematic diagram of a present inventionsystem for separating and/or destroying sour and acid gas depicting anacid gas separation subsystem;

FIG. 3 is a third portion of a schematic diagram of a present inventionsystem for separating and/or destroying sour and acid gas depicting afeed water pretreatment subsystem; and,

FIG. 4 is a four portion of a schematic diagram of a present inventionsystem for separating and/or destroying sour and acid gas depicting adestruction subsystem, a scrubber reactor subsystem and a wastewatertreatment subsystem.

DETAILED DESCRIPTION

At the outset, it should be appreciated that like drawing numbers ondifferent drawing views identify identical, or functionally similar,structural elements of the embodiments set forth herein. Furthermore, itis understood that these embodiments are not limited to the particularmethodology, materials and modifications described and as such may, ofcourse, vary. It is also understood that the terminology used herein isfor the purpose of describing particular aspects only, and is notintended to limit the scope of the disclosed embodiments, which arelimited only by the appended claims.

Unless defined otherwise, all technical and scientific terms used hereinhave the same meaning as commonly understood to one of ordinary skill inthe art to which these embodiments belong. As used herein, the term“average” shall be construed broadly to include any calculation in whicha result datum or decision is obtained based on a plurality of inputdata, which can include but is not limited to, weighted averages, yes orno decisions based on rolling inputs, etc. Furthermore, as used herein,the phrase “to treat . . . to remove” is intended to mean performing anoperation on a component to remove all or some of a constituent withinthe component, wherein the extent of partial removal is furtherdescribed infra, while the phrase “to treat . . . to adsorb” is intendedto mean performing an operation on a component to adsorb all or some ofa constituent within the component, wherein the extent of partialadsorption is further described infra. As used herein, “sweetened gas”is intended to mean a resulting gas stream after removal of some portionof sour and/or acid gas from a starting as stream. For example, asweetened gas stream comprises lower levels of sour and/or acid gas thanthe natural gas stream from which the sweetened gas stream was derived.As used herein, “sour gas” is intended to mean a natural gas streamhaving increased levels of hydrogen sulfide relative to another naturalgas stream, while “acid gas” is intended to mean a natural gas streamhaving increased levels of hydrogen sulfide, carbon dioxide, or similaracidic contaminants relative to another natural gas stream. Furthermore,as used throughout the specification, “sour gas” and “acid gas” are usedinterchangeably, and any reference to one is to be understood to referto either or both. “Waste stream”, as used herein, is intended to mean astream, liquid or gas, that may be disposed of, discharged, burned orotherwise destroyed, as well as a stream that may be include arecoverable energy or recoverable commercial component, e.g., heat,pressure, flow rate, which is recovered prior to disposal, etc.Moreover, as used herein, the phrases “comprises at least one of” and“comprising at least one of” in combination with a system or element isintended to mean that the system or element includes one or more of theelements listed after the phrase. For example, a device comprising atleast one of: a first element; a second element; and, a third element,is intended to be construed as any one of the following structuralarrangements: a device comprising a first element; a device comprising asecond element; a device comprising a third element; a device comprisinga first element and a second element; a device comprising a firstelement and a third element; a device comprising a first element, asecond element and a third element; or, a device comprising a secondelement and a third element. A similar interpretation is intended whenthe phrase “used in at least one of:” is used herein. Furthermore, asused herein, “and/or” is intended to mean a grammatical conjunction usedto indicate that one or more of the elements or conditions recited maybe included or occur. For example, a device comprising a first element,a second element and/or a third element, is intended to be construed asany one of the following structural arrangements: a device comprising afirst element; a device comprising a second element; a device comprisinga third element; a device comprising a first element and a secondelement; a device comprising a first element and a third element; adevice comprising a first element, a second element and a third element;or, a device comprising a second element and a third element.

Moreover, although any methods, devices or materials similar orequivalent to those described herein can be used in the practice ortesting of these embodiments, some embodiments of methods, devices, andmaterials are now described.

The present method and system utilizes the natural resources availablenear natural gas operations, e.g., resources available on a maritimeplatform such as seawater and air, to meet the requirements of thedesired finished product and other outputs. Broadly, the present methodcomprises the following three primary steps: 1) Separate and recoversweetened gas for fuel and/or commercial use using membrane gasseparation technology, where the separation generates various streamswhich may include sweetened gas, sour gas and acid gas; 2) Destroy thesour and/or acid gas using a high temperature incinerator which convertsH₂S gas to SO₂; and, 3) Capture Carbon, e.g., CO₂, and further convertSO₂ to SO₄ by use of a scrubber system reactor that converts SO₂ withseawater and O₂ from the atmosphere to SO₄ and by use of sea water toadsorb CO₂ which can then be discharged into the ocean. It should benoted that SO₄ and CO₂ are natural components of ocean water.

Broadly, the present system and method provides the following benefitsand features, which benefits and features are discussed in greaterdetail infra. The present invention can handle high concentrations ofCO₂ and H₂S, and uses little, if any, amounts of chemicals orconsumables as the primary process ingredients are sour gas, sea waterand air. Little process waste is generated that requires furthertreatment or transportation to shore. The present invention accommodatesfeed gas variations and fluctuations, while it provides sweetened gasthat can be transferred to an alternate location for commercial use,e.g., to shore, injected to enhance oil recovery, or provide fuel gas atthe site of production, e.g., on a maritime platform. Based on the enduse of the sweetened gas, treatment may be required to further sweetengas by removal of additional sour and/or acid gas, as well as otherbyproducts. The present invention recovers energy in the form ofsweetened gas, petroleum liquids and heat recovery from the process ofconverting H₂S to SO₄. It is believed that the total energy recovery canbe in excess of 90%. The present invention captures substantially allCO₂ and H₂S thereby preventing discharge to the atmosphere. Sea waterused in the present system and method is prepared with a continuousfiltration process that is small in footprint and weight. The presentinvention requires little cleaning water and the some waste products canbe directly discharged to the ocean. The present gas pretreatment systemis flexible in design so that it can be tailored to meet various siteconditions and feed stream chemistry. The present system can be run atvarious compressed gas pressures, and multiple steps of liquid and waterseparation are utilized to prepare the gas stream for processing.Moreover, final filtration and adsorption is used to ensure properoperation of the membrane system to minimize operational issues that mayarise due to natural components in the gas mixture or other compoundsthat may be added during oil and gas recovery operations. The presentinvention includes a flexible and robust pretreatment design to preventfouling and destruction of the membranes. Such foulants include but arenot limited to mercury, salts, asphaltenes, waxes, water, compressoroil, lubricants and additives, mercaptans, oxygen, aromatics, glycols,methanol, amines, sulfur, etc. The present membrane system is designedon a site specific basis to meet the specific performance requirements.The present membrane system can be run at high or low pressure andprovide more variation in foot print and purity. The present system andmethod recycle sour and acid gas for higher carbon recovery andoptimizes the quality of the sweetened gas and increases yield bypassing it several times through the separation stage. The membranes canbe staged on the sweetened gas or acid gas stream to deliver differentsystem performance. Depending on the stream chemistry and processdesign, CH₄ can be allowed to pass the membrane in varying amounts orblended downstream to assist in the burning of acid gas. The presentsystem is flexible and can use most membranes on the market, e.g.,spiral or hollow fiber, as well as with various membrane materials ofconstruction. Additional polishing is added to the final gas so it canbe used at the processing location as fuel gas for running generatorsand compressors.

The incinerator is an efficient, high temperature incineratorspecifically designed for H₂S destruction which converts virtually allhydrocarbons and H₂S to water, CO₂ and SO₂. The flue gas from theincinerator is cooled down by a heat exchanger in preparation for feedto the scrubber reactor. The present method is optimized to recoverenergy for further use at the processing location, e.g., on a maritimeplatform. Furthermore, a scrubber having a small footprint uses highsurface area packed media and the natural chemistry in combination withatmospheric air to convert SO₂ to SO₄, while CO₂ is dissolved tocarbonic acid which is buffered by the natural alkalinity of the seawater. A second scrubber reactor zone adds additional sea water tofurther the reaction goals of buffering pH, reducing temperature, andproviding additional oxygen to complete SO₂ conversion along withadditional alkalinity to dissolve and neutralize CO₂. Moreover,additional alkalinity can be used to enhance the reaction and adjust pH,e.g., using standard water treatment chemicals such as lime, soda ash orcaustic soda. The present system and method can utilize feed waterpulled directly from the ocean for processing location at or near anocean. It has been found that using water found deeper in the ocean maybe preferred as it typically has more oxygen present, the water iscooler and includes less suspended solids than at the ocean surface. Itshould be appreciated that the additional dissolved O₂ and lowertemperature aids in the reaction used in the present system and method.Wastewater may need to be post treated, based on the chemistry of theacid gas, for particles, metal and potentially mercury, and the presentinvention provides for such post treatment. The present post treatmentdesign is flexible and depends on the makeup of the dischargedwastewater from the scrubber. For example, if particulate loadingexceeds discharge limits filtration may be required, or if metals ormercury are in the wastewater stream, special ion exchange resin can beused to remove those components to meet discharge requirements. Thepresent invention provides further benefits as wastewater is dischargedbelow the ocean surface, and depending on the wastewater chemistry,discharged in a deep distribution or dilution pipeline. At ocean depthswhich could exceed 1000 feet and long discharge pipelines, residual SO₂will be force into solution and have sufficient reaction time tocomplete conversion to SO₄ before being released to the ocean.Wastewater is slowly dissipated into the ocean across a long slotteddistribution header.

FIGS. 1 through 4 depict a typical embodiment of a present inventionsystem for treatment of a sour or acid gas stream to produce sweetenednatural gas and properly dispose of the acid and sour gas residuals andother waste byproducts. It should be noted that in order to depict thepresent invention with sufficient detail in the figures, the system wasbroken in to portions and distributed across FIGS. 1 through 4. Theconnections between the separate portions are represented by encircledletters. For example, one connection between FIG. 1 and FIG. 3 is shownby the encircled ‘A’. Moreover, the diamond shaped elements designatedby roman numerals, II, III, IV, etc., are included as a representativeexample of the various process characteristics. Such values are merelyprovided as an example and are not intended to limit the scope of theclaimed invention, which invention is limited only by the appendedclaims. Tables 2 and 3 herebelow includes the foregoing example processcharacteristics.

TABLE 2 Flowrate Pressure Temp # Description Phase (LBMOL/HR) (Bars)(deg C.) I Sour/Acid Gas Feed Gas/ 769 1 38 Liquid II Treated Gas Gas226 34.5 1 III Acid Gas Gas 60 1 45 IV Condensed Liquids Gas/ 483 34 25Liquid V Incinerator Flue Gas Gas 578 1 1500 VI Incinerator Flue Gas Gas578 1 150 VII Scrubbed Vent Gas Gas 659 0 80 VIII Seawater Liquid 528 525 IX Scrubber Blowdown Liquid 528 As 60 required X Air Gas 124 1 25 XIAir Gas 564 1 25

TABLE 3 Mole Fraction # H₂O H₂S CO₂ N₂ CH₄ C2+ O₂ SO_(x) I 0.05 0.200.15 0.05 0.22 0.33 0.00 0.00 II 0.00 0.01 0.04 0.16 0.64 0.15 0.00 0.00III 0.03 0.36 0.39 0.00 0.08 0.14 0.00 0.00 IV 0.08 0.26 0.18 0.00 0.040.44 0.00 0.00 V 0.14 0.00 0.09 0.71 0.00 0.00 0.03 0.02 VI 0.14 0.000.09 0.71 0.00 0.00 0.03 0.02 VII 0.07 0.00 0.09 0.94 0.00 0.00 0.040.00 VIII 1.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 IX 0.96 0.00 0.00 0.000.00 0.00 0.00 0.04 X 0.00 0.00 0.00 0.79 0.00 0.00 0.21 0.00 XI 0.000.00 0.00 0.79 0.00 0.00 0.21 0.00

The present invention can accommodate the issue that various feedstreams require slight changes in the process design. It should beappreciated that some subsystems or components may not be required basedon the gas composition and system needs, and that the scope of theinvention is set forth in the claims. The preferred embodiment of theinvention is treatment of natural gas at a production location, e.g., onan off-shore platform, coastal processing facility or inland processingoperations such as a hydrofracturing operation, that has access to oceanwater, or water possessing sufficient alkalinity or added alkalinity,and can discharge byproducts within regulatory requirements, for exampleinto the ocean or a deep well.

Compression

Compression occurring in subsystem 10 is required as the driving forcefor the primary gas separation process to function. Sour gas feed 12enters subsystem 10 at separation unit 14 for the initial liquidsseparation. In the (preferred embodiment of the invention, sour/acid gasfeed 12 is supplied at low pressure, e.g., 0-10 pounds per square inchgauge (psig), is blended with recycled acid gas feed 16 from primarymembrane separator 18, and then flows to knockout drum 20 to separateentrained liquids or condensed liquids generated by the blending to ofsour/acid gas feed 12 and recycle acid gas feed 16. The entrained orcondensed liquids are convey in any known means in the art, e.g., pipe22, to a subsequent processing stage such as gas separation or crudeblending operation. Knockout drum 20 is a typical ASME pressure vesselwith mist eliminator, such as for example the knockout drum manufacturedby Amistco Separation Products, Inc. of Alvin, Tex. The entrained orcondensed liquids, which are at low pressure, are typically rich inheavier hydrocarbons thereby possessing good commercial value.

Subsequently liquid-free sour gas feed 24 passes from knockout drum 20to compressor 26 for compression. Liquid-free sour gas feed 24 iscompressed, for example using a reciprocating gas compressor such as thecompressor manufactured by Ariel Corporation of Mount Vernon, Ohio.Compressor 26 compresses liquid-free sour gas feed 24 to the necessarydriving pressure for separation. Compressor 26 is staged as required toefficiently yield a desired outlet gas pressure and is designed withmaterials and appurtenances to be compatible with sour gas. In thepreferred embodiment of the invention, outlet gas pressure will be500-900 psig and the driver for compressor 26 is an internal combustionengine, such as the driver manufactured by Caterpillar of Peoria, Ill.The driver can utilize the treated gas from the system as a fuel sourcethus making the compression subsystem energy independent.

Gas Pretreatment

After compression in subsystem 10, the sour gas must be conditioned toremove contaminants that may inhibit or impair the membrane separationprocess of subsystem 28. Such conditioning occurs in subsystem 30. Sourgas feed 32 exits compressor 26 at temperatures in excess of 300° F. andmust be cooled to about 120° F. before entry to the membrane separatorsubsystem 28. Sour gas feed 32 is conveyed to primary gas cooler 34. Inthe preferred embodiment of the invention, primary gas cooler 34 is awet surface air cooler such as the wet surface air cooler manufacturedby Niagara Blower Company of Buffalo, N.Y. Primary gas cooler 34 reducesthe temperature of sour gas feed 32 while maintaining an elevatedpressure. Cooling the compressed gas will cause water and heavierhydrocarbons to condense as liquids, thus a secondary liquid separationoperation is necessary. Secondary liquid separator 36 is used to removethe condensed liquids, which liquids need to be removed prior toconveying the sour gas feed to membrane separator subsystem 28.Secondary liquid separator 36 includes a mist eliminator as describedwith respect to knockout drum 20 supra. As described above, such liquidscan be recovered and possess good commercial value. The liquids removedby separator 36 are at a higher pressure and may contain dissolved CO₂and H₂S.

Sour gas feed 38 is cooled further to reduce the dewpoint of the gasentering membrane separator subsystem 28 so that liquids do not condenseon the membrane. Gas heater 40 and secondary gas cooler 42 are standardheat exchangers arranged in a heat recovery circuit for this purpose. Itshould be appreciated that any standard heat exchanging unit thatmaintains separation between hot and cold fluids may be used, e.g.,shell and tube, plate type, etc. Gas heater 40 uses sour gas feed 38from secondary liquid separator 26, i.e., the “hot” fluid, to superheatdry sour gas feed 44 from final liquid separator 46, i.e., the “cold”fluid, to 100-120° F. In the preferred embodiment of the invention,secondary gas cooler 42 uses ocean water feed 48, i.e., the “cold”fluid, to cool sour gas feed 50 from gas heater 40, i.e., the “hot”fluid, to the extent that the differential temperature between oceanwater feed 48 and sour gas feed 50 will typically 60-90° F. depending onthe temperature of ocean water feed 48. Condensed liquids exitingsecondary gas cooler 42 are removed from sour gas feed 52 using liquidseparator 46 which includes a mist eliminator as previously describedabove. As also described above, the condensed liquids may be recoveredand possess good commercial value. The final step in subsystem 30provides gas conditioning and filtration of sour gas feed 56 prior toconveyance to membrane separator subsystem 28. Gas conditioning andfiltration unit 58 typically removes particulates and trace water vaporfrom sour gas feed 56. In the preferred embodiment of the invention, gasconditioning and filtration unit 58 comprises an ASME pressure vesselfilled with activated carbon adsorbent or other purification mediafollowed by a cartridge filter housing with filter such as the cartridgefilter housing manufactured by Precision Filtration Products ofPennsburg, Pa.

Liquids obtained from knockout drum 20, secondary liquid separator 36,and liquid separator 46 are removed from the system at output 59, andutilized for further purposes such as gas separation or crude blending.

Acid Gas Separation

Acid gas separation occurring in subsystem 28 is the completion of thepresent invention separation process. Primary membrane separator 18provides the bulk separation of acid gas from sour gas feed 64. In otherwords, primary membrane separator 18 provides the physical separation ofvarious types of gases with a membrane that allows certain gases topermeate through the membrane at different rates. Membranes are selectedsuch that the mass transfer rate across the membrane of H₂S and CO₂ aremuch higher than CH₄, thereby generating sweetened natural as stream 66and acid gas stream 72 that requires further handling. In the preferredembodiment of the invention, the membranes are spiral wound celluloseacetate membrane elements such as the membrane elements manufactured byUOP of Des Plaines, Ill., or hollow fibers such as the hollow fibersmanufactured by Air Liquide Medal of Baltimore, Md. The membraneelements are loaded into tubular housings, the quantity and arrangementof which is dictated by the quantity of gas to be processed and desiredlevel of purification.

In the preferred embodiment of the invention, the membranes and housingsare arranged in two sets or stages. In the first stage, acid gaspermeate is removed as acid gas stream 72 and sent to the acid gasdestruction equipment of subsystem 74. Sweetened gas stream 66 from thefirst stage may be drawn off as treated gas for enhanced oil recovery atoutput 76, drawn off as treated gas to a conveyance system at output 78or flows to the second stage where acid gas is further removed. Acid gasfraction 79 is recycled to the front of the process, i.e., subsystem 10,as described above in order to drive greater separation through themembrane by increasing acid gas partial pressure in the sour gas feed12. Sweetened natural gas stream 66 is collected for sale or use at theprocessing location. In the preferred embodiment of the invention,sweetened natural gas stream 66 generated by primary membrane separator18 is used for on-board fuel gas service which requires higher puritythan will typically be generated by primary membrane separator 18. If itis desired to treat sweetened gas stream 66 to a higher purity, the highpressure gas exiting primary membrane separator 18 can be furthertreated to separate additional sour and/or acid gas. Polishing membraneseparator 80 is constructed as an array of membrane modules similar to,but in smaller quantity than, primary membrane separator 18. Acid gasstream 82 from polishing membrane separator 80 may be combined with acidgas fraction 79 and flows to the initial liquids separation unit, i.e.,subsystem 10, for recycling as previously described, while the treatedgas stream from polishing membrane separator 80 flows to output 84 forfurther use. In some circumstances, additional polishing may benecessary, thereby requiring the inclusion of polisher 85. In suchcircumstances, there are several known technologies that can be used,where some technologies can be regenerated and some not. For example,iron pellet filters can remove traces of H₂S. In view of the foregoing,it should be appreciated that ‘polishing’ in combination with a gasstream as used herein is intended to mean treating of the gas stream toa higher purity level, e.g., removing traces of H₂S and othercontaminates.

Acid Gas Destruction

Acid gas destruction occurs in subsystem 74. The acid gas permeate fromprimary membrane separator 18 contains high concentration (70-80 mole %)of acid gases, typically H₂S and CO₂. The H₂S must be destroyed and theCO₂ and byproducts of the H₂S destruction must be disposed of in anenvironmentally sound way. The acid gas permeate also contains somehydrocarbons (10-15 mole %) that permeate through the membranes ofprimary membrane separator 18. These hydrocarbon compounds are requiredas additional fuel to burn the acid gas mixture. The first step in theprocess is to oxidize, i.e., burn, H₂S in high efficiency incinerator87, such as the incinerator manufactured by Aecometric Corporation ofRichmond Hill, Ontario, Canada. Incinerator 87 converts H₂S to sulfurdioxide. The oxidation reaction occurs at low pressure, e.g., <5 psig,and at high temperature, e.g., 2700° F. Clean atmospheric air is used asa source of combustion air as well as temperature control in incinerator87. Incinerator air feed blower 88 feeds combustion air to incinerator87. A representative example of blower 88 is a standard low pressurerotary lobe blower such as the blower manufactured by Kaeser Compressorsof Fredericksburg, Va. It should be appreciated that any blower capableof meeting the flow and pressure requirements may be used, e.g., rotarylobe, centrifugal or regenerative turbine blowers.

Flue Gas Cooler and Heat Recovery

Flue gas cooling and heat recovery occurs in subsystem 89. Heat recoveryexchanger 90 receives incinerator flue gas at a temperature ofapproximately 2700° F., which must be cooled ahead of the finalscrubbing stage of subsystem 91 prior to discharge to the atmosphere viaoutput 92. In the preferred embodiment of the invention, heat isrecovered through waste heat recovery unit 93 such as the recovery unitmanufactured by indeck Power Equipment Co. of Wheeling, Ill. Therecovered heat may be used for various utility and processingrequirements, Waste heat recovery unit 93 is designed to reduce flue gastemperature to <300° F. If necessary, further cooling to <140° F. can beachieved using a standard shell and tube or plate and frame heatexchanger with ocean water as the cooling fluid.

Scrubber Reactor

Scrubbing occurs in subsystem 91. In the preferred embodiment of theinvention, seawater provides the oxygen and alkalinity required forscrubbing the SO₂ from the cooled flue gas and converting the SO₂ tosoluble SO₄. Additional chemicals may be added to adjust scrubber waterstream 96 alkalinity. Such chemicals may include but are not limited tolime, bicarbonate, or sodium hydroxide. This chemical addition step isdescribed below in the section discussing subsystem 98. This chemicaladdition step may also be used where the feed water chemistry requiresadditional alkalinity, where ocean water is not available, or where amore rapid reaction is required. Provided sufficient treatment occurs,the ocean is a suitable discharge point for products of the abovedescribed incineration and scrubbing reactions, such products alreadyappear naturally in sea water, namely CO₂ and SO₄.

Scrubber reactor 100 comprises primary reactor zone 102 which absorbsSO₂ into the seawater. In the preferred embodiment of the invention, astandard counter current scrubbing tower is filled with random packingmedia such as the scrubbing tower manufactured by Rasching Jaeger RingDivision of Sun Valley, Calif. Thus, scrubber reactor 100 is used toscrub sulfur dioxide from the cooled flue gas. The flue gas flows upthrough a high surface area packing along with introduced air. Seawateris introduced at the top of scrubber reactor 100 and flows countercurrent to the flue gas and air mixture. It should be appreciated thatthe packing is coated with seawater and provides for a large transfersurface area for transfer of sulfur dioxide from the flue gas to theliquid phase, i.e., seawater. The alkalinity inherent in seawater isrequired to reduce the sulfur dioxide concentration in the treated fluegas to parts per million (ppm) levels for atmospheric discharge. Oncedissolved, sulfur dioxide reacts with water to form sulfite anionsaccording to the reaction shown in Equation (1) herebelow.

SO₂+H₂O→H⁺+HSO₃ ⁻  (1)

Oxygen dissolved in the scrubber water further reacts with the dissolvedsulfite to form sulfate in anions. Provided the scrubber water meets thedischarge requirements, the water flows back into the sea with amarginally higher concentration of sulfate and CO₂. Scrubber reactor 100further comprises secondary reactor zone 104 where additional seawateris added to a scrubber sump. The additional seawater provides addedoxygen, alkalinity to adjust pH and temperature. Scrubber air feedblower 106 provides introduced air as described above. Blower 106 may bea rotary lobe blower as described above, and provides additional oxygenfor the SO₂ conversion reaction requirements. Scrubbed gas exitsscrubber reactor 100 via output 107.

Wastewater Treatment

Wastewater treatment occurs in subsystem 108. A sour gas stream maycontain contaminates which may end up in the scrubber water therebyrequiring treatment prior to discharge in the ocean. These contaminatesmay include heavy metals and particulate material. In the preferredembodiment of the invention, final treatment is an ocean pipe line witha dilution header to slowly release the water in the ocean. Thispipeline is deep in the ocean and over a long distance to provide for aslow release of wastewater into the ocean at depths where the pressurewill ensure dissolved gases will remain in solution and that anyresidual SO₃ will convert to SO₄. Wastewater quickly blends with theocean water equalizing pH, total dissolved solids (TDS) and temperature.Wastewater stream 110 exits scrubber reactor 100 and is conveyed todischarge pump 112. Pump 112 may be a standard centrifugal pump such asthe centrifugal pump manufactured by Goulds Pumps of Seneca Falls, N.Y.,It should be appreciated that any pump capable of transferring water atthe quantity and pressure required would be suitable, e.g., centrifugal,piston or axial flow turbine pumps. Pump 112 pressurizes water throughthe necessary wastewater treatment equipment and to the ocean dischargepipeline (not shown). Discharge pressure is set as required for thedepth of discharge, which is typically greater than 50 psi. Particlefilter 114 removes particles generated during the scrubbing process ifthey exceed regulatory guidelines. Filters may be of a disposable typefor low total suspended solid (TSS) levels or a cleanable type asdescribed in ocean feed water pretreatment infra. Metal removal system116 removes metals that are present in varying quantities depending onthe quality of the sour gas. These metals may need to be treated todischarge regulatory requirements. Treatment consists of specificchelating ion exchange resin that will remove metals from salty seawatersuch as Dow Amberlite™ IRC748 (a macroporous styrene divinylbenzen resinwith iminodiacetic acid functional groups) sold by Dow Chemical locatedin Midland, Mich. These resins can be regenerated on site or removed andsent to a land based facility for regeneration. If necessary, mercuryremoval system 117 is included prior to discharging wastewater to theocean via output 118. Mercury removal unit 117 is an ion exchange devicethat incorporates resins that have a specific affinity for mercury,e.g., DOW XUS-43604 (a thiol type resin containing the —SH functionalgroup) sold by Dow Chemical located in Midland, Mich.

Ocean Feed Water Pretreatment

Ocean feed water pretreatment occurs in subsystem 98. Ocean water has asubstantial amount of total suspended solids (TSS). The TSS must bereduced to prevent plugging and fouling of the process equipment. It isadvantageous to collect ocean water from a sufficient depth as deeperwater contains more dissolved oxygen and less suspended solids. Waterfeed 120 is pumped under pressure to continuous particle removal screen122 which contains a series of vertical wedge wire screens to capturelarge particles in the range of 200 microns and above. An example of asuitable screen is the particle removal screen manufactured by SAMCOTechnologies of Buffalo, N.Y. One screen element is backwashed at a timethus maintaining continuous forward flow. Continuous particle removalscreen 122 is designed to provide primary filtration. The backwash fromscreen 122 is sent back to the ocean via output 123. Water exitingcontinuous particle removal screen 122 is fed to a finer filteringdevice, i.e., continuous particle removal filter 124, that contains aseries of vertical septa with filter media. An example of a suitableparticle removal filter is the filter manufactured by SAMCO Technologiesof Buffalo, N.Y. The media micron retention can be adjusted to theprocess requirements. Continuous particle removal filter 124 is designedto capture particles in the range of 20-100 microns. One filter elementis backwashed at a time thus maintaining continuous forward flow.Continuous particle removal filter 124 is design to provide polishingfiltration. The backwash from continuous particle removal filter 124 issent back to the ocean via output 123. Chemical feeder 126, fed by waterstream 128, may be included as needed for alkalinity adjustment of waterfeed 120. Chemical feeder 126 may also be used to condition a watersupply that is not initially obtained from the ocean or other seawatersource. Thus, the present invention is not limited to use on or near anocean, the present invention may be used at any location where asufficient water supply can be obtained or provided.

It should be appreciated that although the foregoing examples arelargely described relative to use on a maritime platform, the presentinvention may also be used in a variety of other locations. For example,the present invention may be used at a coastal processing facility or aninland hydrofracturing operation. Such variations are within the spiritand scope of the claimed invention. Moreover, the present methods andsystem can be used for general gas purification as well as thepurification of sour and acid gas, on maritime platforms as well as onland based operations. Equipment is selected based on requirements ofsmall foot print and weight, continuous cleaning, ease of maintenance,flexible media types and ease of use and maintenance.

It will be appreciated that various of the above-disclosed and otherfeatures and functions, or alternatives thereof, may be desirablycombined into many other different systems or applications. Variouspresently unforeseen or unanticipated alternatives, modifications,variations or improvements therein may be subsequently made by thoseskilled in the art which are also intended to be encompassed by thefollowing claims.

What is claimed is:
 1. A system adapted to separate a natural gas feedstream into a sweetened gas stream at least one liquid waste stream andat least one gaseous waste stream, and to discharge, recover or destroythe at least one liquid waste stream and the at least one gaseous wastestream, the system comprising: a compression subsystem adapted to treatthe natural gas feed stream to remove a first portion of the at leastone liquid waste stream and to increase the natural gas feed stream to aprocess pressure greater than an initial entering pressure to form apressurized natural gas stream; a gas pretreatment subsystem adapted totreat the pressurized natural gas stream to remove a second portion ofthe at least one liquid waste stream and to cool and filter thepressurized natural gas stream to form a filtered natural gas stream; anacid gas separation subsystem adapted to separate the filtered naturalgas stream into the sweetened gas stream and a first portion of the atleast one gaseous waste stream; and, a destruction subsystem adapted toincinerate the first portion of the at least one gaseous waste stream toform a flue gas.
 2. The system of claim 1 wherein the compressionsubsystem comprises at least one of: a liquid separation unit adapted totreat the natural gas feed to remove the first portion of the at leastone liquid waste stream; and, a compressor adapted to increase apressure of the natural gas feed stream to the process pressure.
 3. Thesystem of claim 1 wherein the gas pretreatment subsystem comprises atleast one of: a gas cooler adapted to cool the pressurized natural gasstream; a liquid separation unit adapted treat the pressurized naturalgas stream to remove the second portion of the at least one liquid wastestream; a heat exchanger adapted to cool the pressurized natural gasstream; and, a gas filter adapted to treat the pressurized natural gasstream to remove particulates and water vapor.
 4. The system of claim 1wherein the acid gas subsystem comprises at least one of: a firstmembrane separator adapted to separate the filtered natural gas streaminto the sweetened gas stream and the first portion of the at least onegaseous waste stream; a second membrane separator adapted to treat thesweetened gas stream to remove a second portion of the at least onegaseous waste stream; and, a polisher adapted to polish the sweetenedgas stream.
 5. The system of claim 1 wherein the destruction subsystemcomprises at least one of: an incinerator adapted to combust the firstportion of the at least one gaseous waste stream; and, a in heatexchanger adapted to cool the flue gas.
 6. The system of claim 1 furthercomprising: a feed water pretreatment subsystem adapted to filter awater stream to form a filtered water stream, wherein the filtered waterstream cools the pressurized natural gas stream in the gas pretreatmentsubsystem.
 7. The system of claim 6 wherein the feed water pretreatmentsubsystem comprises at least one of a first continuous particle filteradapted to filter the water stream; a second continuous particle filteradapted to filter the water stream; and, a chemical feeder adapted tocondition the filtered water stream.
 8. The system of claim 6 furthercomprising: a scrubber reactor subsystem adapted to receive the filteredwater stream and to remove at least one portion of the flue gas usingthe filtered water stream to form a vent gas stream and a wastewaterstream, wherein the vent gas is exhausted to the atmosphere.
 9. Thesystem of claim 8 wherein the scrubber reactor subsystem comprises atleast one of: a scrubber reactor adapted to remove at least one portionof the flue gas using the filtered water stream; and, a blower adaptedto provide air to the scrubber reactor.
 10. The system of claim 8further comprising: a wastewater treatment subsystem adapted to filterthe wastewater stream to form a discharge water stream.
 11. The systemof claim 10 wherein the wastewater treatment subsystem comprises atleast one of: a particulate filter adapted to remove particulates fromthe wastewater stream; a metal unit adapted to remove metal from thewastewater stream; and, a mercury unit adapted to remove mercury fromthe wastewater stream.
 12. A method for separating a natural gas feedstream into a sweetened gas stream, at least one liquid waste stream andat least one gaseous waste stream, and for discharging, recovering ordestroying the at least one liquid waste stream and at least one gaseouswaste stream, the method comprising: a) treating the natural gas feedstream to remove a first portion of the at east one liquid waste stream;b) pressurizing the natural gas feed stream to a process pressuregreater than an initial entering pressure to form a pressurized naturalgas stream; c) treating the pressurized natural gas stream to remove asecond portion of the at least one liquid waste stream; d) cooling andfiltering the pressurized natural gas stream to form a filtered naturalgas stream; e) separating the filtered natural gas stream into thesweetened gas stream and a first portion of the at least one gaseouswaste stream; and, f) incinerating the first portion of the at least onegaseous waste stream to form a flue gas.
 13. The method of claim 12further comprising: c1) filtering a water stream to form a filteredwater stream, wherein the filtered water stream in part cools thepressurized natural gas stream in step d).
 14. The method of claim 13further comprising: g) removing at least one portion of the flue gasusing the filtered water stream to form a vent gas stream and awastewater stream and, h) exhausting the vent gas to the atmosphere. 15.The method of claim 14 further comprising: i) filtering the wastewaterstream to form a discharge water stream.